About 63% of the world's electric power and 70% of the electric power produced in the United States is generated from the burning of fossil fuels like coal, oil, or natural gas at electric power plants. Such fuel is burned in a combustion chamber at the power plant to produce heat used to convert water in a boiler to steam. This steam is then superheated and introduced to huge steam turbines whereupon it pushes against the fanlike blades of the turbine to rotate a shaft. This spinning shaft, in turn, turns the rotor of an electric generator to produce electricity.
Once the steam has passed through the turbine, it enters a condenser where it passes around pipes carrying cooling water, which absorbs heat from the steam. As the steam cools, it condenses into water which can then be pumped back to the boiler to repeat the process of heating it into steam once again. In many power plants, this water in the condenser pipes that has absorbed this heat from the steam is pumped to a spray pond or cooling tower to be cooled. The cooled water can then be recycled through the condenser or discharged into lakes, rivers, or other water bodies.
Eighty-nine percent of the coal mined in the United States is used as the heat source for electric power plants. Unlike petroleum and natural gas, the available supplies of coal that can be economically extracted from the earth are plentiful.
There are four primary types of coal: anthracite, bituminous, subbituminous, and lignite. While all four types of these coals principally contain carbon, hydrogen, nitrogen, oxygen, and sulfur, as well as moisture, the specific amounts of these solid elements and moisture contained in coal varies widely. For example, the highest ranking anthracite coals contain about 98% wt carbon, while the lowest ranking lignite coals (also called “brown coal”) may only contain about 30% wt carbon. At the same time, the amount of moisture may be less than 1% in anthracite and bituminous coals, but 25-30% wt for subbituminous coals like Powder River Basin (“PRB”), and 35-40% wt for North American lignites. For Australia and Russia, these lignite moisture levels may be as high as 50% and 60%, respectively. These high-moisture subbituminous and lignite coals have lower heating values compared with bituminous and anthracite coals because they produce a smaller amount of heat when they are burned. Moreover, high fuel moisture affects all aspects of electric power unit operation including performance and emissions. High fuel moisture results in significantly lower boiler efficiencies and higher unit heat rates than is the case for higher-rank coals. The high moisture content can also lead to problems in areas such as fuel handling, fuel grinding, fan capacity, and high flue gas flow rates.
Bituminous coals have been the most widely used rank of coal in the U.S. for electric power production because of their abundance and relatively high heating values. However, they also contain medium to high levels of sulfur. As a result of increasingly stringent environmental regulations like the Clean Air Act in the U.S., electric power plants have had to install costly scrubber devices in front of chimneys at of these plants to prevent the sulfur dioxide (“SO2”), nitrous oxides (“NOx”), and fly ash that result from burning these coals to pollute the air.
Lower rank coals like subbituminous and lignite coals have gained increasing attention as heat sources for power plants because of their low sulfur content and cost. However, they still produce sufficient levels of SO2, NOx, and fly ash when burned such that treatment of the flue gas is required to comply with federal and state pollution standards. Additionally, ash and sulfur are the chief impurities appearing in coal. The ash consists principally of mineral compounds of aluminum, calcium, iron, and silicon. Some of the sulfur in coal is also in the form of minerals—particularly pyrite, which is a compound of iron and sulfur. The remainder of the sulfur in coal is in the form of organic sulfur, which is closely combined with the carbon in the coal.
It has previously been recognized within the industry that heating coal reduces its moisture, and therefore enhances the rank and heating value (BTU per pound) of the coal by drying the coal. Prior to its combustion in hot water boilers, drying of the coal can enhance the resulting efficiency of the boiler.
A wide variety of dryer devices have been used within the prior art to dry coal, including rotary kilns (U.S. Pat. No. 5,103,743 issued to Berg), cascaded whirling bed dryers (U.S. Pat. No. 4,470,878 issued to Petrovic et al.), elongated slot dryers (U.S. Pat. No. 4,617,744 issued to Siddoway et al.), hopper dryers (U.S. Pat. No. 5,033,208 issued to Ohno et al.), traveling bed dryers (U.S. Pat. No. 4,606,793 issued to Petrovic et al.), and vibrating fluidized bed dryers (U.S. Pat. No. 4,444,129 issued to Ladt). Also well-known within the industry are fluidized-bed dryers or reactors in which a fluidizing medium is introduced through holes in the bottom of the bed to separate and levitate the coal particles for improved drying performance. The fluidizing medium may double as a direct heating medium, or else a separate indirect heat source may be located within the fluidized bed reactor. See, e.g., U.S. Pat. Nos. 5,537,941 issued to Goldich; U.S. Pat. No. 5,546,875 issued to Selle et al.; U.S. Pat. No. 5,832,848 issued to Reynoldson et al.; U.S. Pat. Nos. 5,830,246, 5,830,247, and 5,858,035 issued to Dunlop; U.S. Pat. No. 5,637,336 issued to Kannenberg et al.; U.S. Pat. No. 5,471,955 issued to Dietz; U.S. Pat. No. 4,300,291 issued to Heard et al.; and U.S. Pat. No. 3,687,431 issued to Parks.
Many of these conventional drying processes, however, have employed very high temperatures and pressures. For example, the Bureau of Mines process is performed at 1500 psig, while the drying process disclosed in U.S. Pat. No. 4,052,168 issued to Koppelman requires pressures of 1000-3000 psi. Similarly, U.S. Pat. No. 2,671,968 issued to Criner teaches the use of updrafted air at 1000° F. Likewise, U.S. Pat. No. 5,145,489 issued to Dunlop discloses a process for simultaneously improving the fuel properties of coal and oil, wherein a reactor maintained at 850-1050° F. is employed. See also U.S. Pat. Nos. 3,434,932 issued to Mansfield (1400-1600° F.); and 4,571,174 issued to Shelton (≦1000° F.).
The use of such very high temperatures for drying or otherwise treating the coal requires enormous energy consumption and other capital and operating costs that can very quickly render the use of lower-ranked coals economically unfeasible. Moreover, higher temperatures for the drying process create another emission stream that needs to be managed as volatiles are driven off. Further complicating this economic equation is the fact that prior art coal drying processes have often relied upon the combustion of fossil fuels like coal, oil, or natural gas to provide the very heat source for improving the heat value of the coal to be dried. See, e.g., U.S. Pat. Nos. 4,533,438 issued to Michael et al.; U.S. Pat. No. 4,145,489 issued to Dunlop; U.S. Pat. No. 4,324,544 issued to Blake; 4,192,650 issued to Seitzer; U.S. Pat. No. 4,444,129 issued to Ladt; and U.S. Pat. No. 5,103,743 issued to Berg. In some instances, this combusted fuel source may constitute coal fines separated and recycled within the coal drying process. See, e.g., U.S. Pat. Nos. 5,322,530 issued to Merriam et al; U.S. Pat. No. 4,280,418 issued to Erhard; and U.S. Pat. No. 4,240,877 issued to Stahlherm et al.
Efforts have therefore been made to develop processes for drying coal using lower temperature requirements. For example, U.S. Pat. No. 3,985,516 issued to Johnson teaches a drying process for low-rank coal using warm inert gas in a fluidized bed within the 400-500° F. range as a drying medium. U.S. Pat. No. 4,810,258 issued to Greene discloses the use of a superheated gaseous drying medium to heat the coal to 300-450° F., although its preferred temperature and pressure is 850° F. and 0.541 psi. See also U.S. Pat. Nos. 4,436,589 and 4,431,585 issued to Petrovic et al. (392° F.); 4,338,160 issued to Dellessard et al. (482-1202° F.); U.S. Pat. No. 4,495,710 issued to Ottoson (400-900° F.); U.S. Pat. No. 5,527,365 issued to Coleman et al. (302-572° F.); U.S. Pat. No. 5,547,549 issued to Fracas (500-600° F.); U.S. Pat. Nos. 5,858,035 issued to Dunlop; and U.S. Pat. Nos. 5,904,741 and 6,162,265 issued to Dunlop et al. (480-600° F.).
Several prior art coal drying processes have used still lower temperatures—albeit, only to dry the coal to a limited extent. For example, U.S. Pat. No. 5,830,247 issued to Dunlop discloses a process for preparing irreversibly dried coal using a first fluidized bed reactor with a fluidized bed density of 20-40 lbs/ft3, wherein coal with a moisture content of 15-30% wt, an oxygen content of 10-20%, and a 0-2-inch particle size is subjected to 150-200° F. for 1-5 minutes to simultaneously comminute and dewater the coal. The coal is then fed to a second fluidized bed reactor in which it is coated with mineral oil and then subjected to a 480-600° F. temperature for 1-5 minutes to further comminute and dehydrate the product. Thus, it is apparent that not only is this process applied to coals having relatively lower moisture contents (i.e., 15-30%), but also the coal particles are only partially dewatered in the first fluidized bed reactor operated at 150-200° F., and the real drying takes place in the second fluidized bed reactor that is operated at the higher 480-600° F. bed temperature.
Likewise, U.S. Pat. No. 6,447,559 issued to Hunt teaches a process for treating coal in an inert atmosphere to increase its rank by heating it initially at 200-250° F. to remove its surface moisture, followed by sequentially progressive heating steps conducted at 400-750° F., 900-1100° F., 1300-1550° F., and 2000-2400° F. to eliminate the water within the pores of the coal particles to produce coal with a moisture content and volatiles content of less than 2% and 15%, respectively, by weight. Again, it is clear that the initial 200-250° F. heating step provides only a limited degree of drying to the coal particles.
One of the problems that can be encountered with the use of fluidized bed reactors to dry coal is the production of large quantities of fines entrapped in the fluidizing medium. Especially at higher bed operating conditions, these fines can spontaneously combust to cause explosions. Therefore, many prior art coal drying processes have resorted to the use of inert fluidizing gases within an air-free fluidized bed environment to prevent combustion. Examples of such inert gas include nitrogen, carbon dioxide, and steam. See, e.g., U.S. Pat. Nos. 3,090,131 issued to Waterman, Jr.; U.S. Pat. No. 4,431,485 issued to Petrovic et al.; U.S. Pat. Nos. 4,300,291 and 4,236,318 issued to Heard et al.; U.S. Pat. No. 4,292,742 issued to Ekberg; U.S. Pat. No. 4,176,011 issued to Knappstein; U.S. Pat. No. 5,087,269 issued to Cha et al.; U.S. Pat. No. 4,468,288 issued to Galow et al.; U.S. Pat. No. 5,327,717 issued to Hauk; U.S. Pat. No. 6,447,559 issued to Hunt; and 5,904,741 issued to Dunlop et al. U.S. Pat. No. 5,527,365 issued to Coleman et al. provides a process for drying low-quality carbonaceous fuels like coal in a “mildly reducing environment” achieved through the use of lower alkane inert gases like propane or methane. Still other prior art processes employ a number of heated fluidizing streams maintained at progressively decreasing temperatures as the coal travels through the length of the fluidized bed reactor to ensure adequate cooling of the coal in order to avoid explosions. See, e.g., U.S. Pat. No. 4,571,174 issued to Shelton; and U.S. Pat. No. 4,493,157 issued to Wicker.
Still another problem previously encountered by the industry when drying coal is its natural tendency to reabsorb water moisture in ambient air conditions over time after the drying process is completed. Therefore, efforts have been made to coat the surface of the dried coal particles with mineral oil or some other hydrocarbon product to form a barrier against adsorption of moisture within the pores of the coal particles. See, e.g., U.S. Pat. Nos. 5,830,246 and 5,858,035 issued to Dunlop; U.S. Pat. No. 3,985,516 issued to Johnson; and U.S. Pat. Nos. 4,705,533 and 4,800,015 issued to Simmons.
In order to enhance the process economics of drying low-rank coals, it is known to use waste heat streams as supplemental heat sources to the primary combustion fuel heat source. See U.S. Pat. No. 5,322,530 issued to Merriam et al. This is particularly true within coking coal production wherein the cooling gas heated by the hot coke may be recycled for purposes of heating the drying gas in a heat exchanger. See, e.g., U.S. Pat. Nos. 4,053,364 issued to Poersch; U.S. Pat. No. 4,308,102 issued to Wagener et al.; U.S. Pat. No. 4,338,160 issued to Dellessard et al.; U.S. Pat. No. 4,354,903 issued to Weber et al.; U.S. Pat. No. 3,800,427 issued to Kemmetmueller; U.S. Pat. No. 4,533,438 issued to Michael et al.; and U.S. Pat. No. 4,606,793 and U.S. Pat. No. 4,431,485 issued to Petrovic et al. Likewise, flue gases from fluidized bed combustion furnaces have been used as a supplemental heat source for a heat exchanger contained inside the fluidized bed reactor for drying the coal. See, e.g., U.S. Pat. Nos. 5,537,941 issued to Goldich; and U.S. Pat. No. 5,327,717 issued to Hauk. U.S. Pat. No. 5,103,743 issued to Berg discloses a method for drying solids like wet coal in a rotary kiln wherein the dried material is gasified to produce hot gases that are then used as the combustion heat source for radiant heaters used to dry the material within the kiln. In U.S. Pat. No. 4,284,476 issued to Wagener et al., stack gas from an associated metallurgical installation is passed through hot coke in a coke production process to cool it, thereby heating the stack gas which is then used to preheat the moist coal feed prior to its conversion into coke.
None of these prior art processes, however, appear to employ a waste heat stream in a coal drying operation as the sole source of heat used to dry the coal. Instead, they merely supplement the primary heat source which remains combustion of a fossil fuel like coal, oil or natural gas. Thus, the process economics for drying the coal products, including low-rank coals, continues to be limited by the need to burn fossil fuels in order to dry a fossil fuel (i.e., coal) to improve its heat value for firing a boiler in a process plant (e.g., an electric power plant).
Coal mining companies typically clean their coal products to remove impurities before supplying them to end users like electric power plants and coking production plants. After sorting the pieces of coal by means of a screening device to form coarse, medium, and fine streams, these three coal streams are delivered to washing devices in which the coal particles are mixed with water. Using the principle of specific gravity, the heaviest pieces containing the largest amounts of impurities settle to the bottom of the washer, whereupon they drop into a refuse bin for subsequent disposal. The cleaned coal particles from the three streams are then combined together again and dried by means of vibrators, jigs, or hot-air blowers to produce the final coal product ready for shipment to the end user.
While the cleaning process employed by coal mining operations removes much of the ash from the coal, it has little effect on sulfur, since the organic sulfur is closely bound to the carbon within the coal. Thus, other methods need to be used to further purify the coal prior to its combustion. Methods are known in industry for separating different types of particulate materials. For example, U.S. Pat. No. 3,852,168 issued to Oetiker discloses a large machine for separating corn kernels from husk parts, wherein they are subjected to vibration and pulsated air currents. U.S. Pat. No. 5,244,099 issued to Zaltzman et al., on the other hand, teaches the delivery of granular materials through an upwardly inclined trough through which a fluidizing gas is forced from the bottom of the trough to create a fluidized material bed. A vertical oscillatory motion is also imparted to the trough to assist in the separation of the various components contained in the material mixture. Less dense components of the mixture rise to the surface of the fluidized bed, while the denser components settle to the bottom. At the output end of the trough, a stream splitter can be used to recover different layers of materials. This apparatus is good for separating agricultural products and sand.
It is known in the prior art that under some circumstances a fluidized bed may be used without the addition of mechanical vibration or vertical oscillation to achieve particle separation. For example, U.S. Pat. No. 4,449,483 issued to Strohmeyer uses a heated fluidized bed dryer to treat municipal trash and remove heavier particles like glass from the trash before its combustion to produce heat. Meanwhile, U.S. Pat. No. 3,539,001 issued to Binnix et al. classifies materials from an admixture by means of intermediate selective removal of materials of predetermined sizes and specific gravities. The material mixture travels along a downwardly sloped screen support and is suspended by upwardly directed pneumatic pulses. U.S. Pat. No. 2,512,422 issued to Fletcher et al. again uses a downwardly inclined fluidized bed with upwardly directed pulses of air, wherein small particles of coal can be separated and purified from a coal mixture by providing holes in the top of the fluidized bed unit of a sufficient cross sectional area relative to the total cross sectional area of the bed to control the static pressure level within the fluidized bed to prevent the small particles of higher specific gravity from rising within the coal bed.
The process and devices disclosed in these Strohmeyer, Binnix, and Fletcher patents, however, all seem to be directed to the separation of different constituents within an admixture having a relatively large difference in specific gravity. Such processes may work readily to separate nuts, bolts, rocks, etc. from coal, however, they would not be expected to separate coal particles containing organic sulfur from coal particles largely free of sulfur since the specific gravities of these two coal fractions can be relatively close.
Another air pollutant of great concern is mercury, which occurs naturally in coal. Regulations promulgated by the U.S. Environmental Protection Agency (“EPA”) require coal-fired power plants to dramatically reduce the mercury levels contained in their flue gases by 2010. Major efforts within the industry have focused upon the removal of mercury from the flue gas by the use of carbon-based sorbents or optimization of existing flue gas emissions control technologies to capture the mercury. However, utilization of carbon sorbent-based scrubber devices can be very expensive to install and operate. Moreover, currently existing emissions control equipment can work less well for high-rank coals (anthracite and bituminous) vs. low-rank coals (subbitumionous and lignite).
Western Research Institute has therefore developed and patented a pre-combustion thermal process for treating low-rank coals to remove the mercury. Using a two-zone reactor, the raw coal is heated in the first zone at approximately 300° F. to remove moisture which is purged from the zone with a sweep gas. The dried coal is then transferred to a second zone where the temperature is raised to approximately 550° F. Up to 70-80% of the mercury contained in the coal is volatilized and swept from the zone with a second sweep gas stream. The mercury is subsequently separated from the sweep gas and collected for disposal. See Guffey, F. D. & Bland, A. E., “Thermal Pretreatment of Low-Ranked Coal for Control of Mercury Emissions,” 85 Fuel Processing Technology 521-31 (2004); Merriam, N. W., “Removal of Mercury from Powder River Basin Coal by Low-Temperature Thermal Treatment,” Topical Report WRI-93-R021 (1993); U.S. Pat. No. 5,403,365 issued to Merriam et al.
However, this pre-combustion thermal pretreatment process is still capital-intensive in that it requires a dual zone reactor to effectuate the drying and mercury volatilization steps. Moreover, an energy source is required to produce the 550° F. bed temperature. Furthermore, 20-30% of the mercury cannot be removed from the coal by this process, because it is tightly bound to the carbon contained in the coal. Thus, expensive scrubber technology will still be required to treat flue gas resulting from combustion of coal pretreated by this method because of the appreciable levels of mercury remaining in the coal after completion of this thermal pre-treatment process.
Therefore, the ability to pre-treat particulate material like coal with a fluidized bed operated at a very low temperature without mechanical or chemical additives in order to separate and remove most of the pollutant constituents within the coal (e.g., mercury and sulfur) would be desirable. Such a process could be applied to all ranks of coal, and would alleviate the need for expensive scrubber technology for treatment of flue gases after combustion of the coal.
The concerted use of waste heat sources available within industrial plants using boilers that would otherwise be lost as the exclusive heat source for drying the coal prior to its introduction to the boiler furnace to improve the process economics of using low-rank coals like subbituminous and lignite coal would also be desirable. Such low-rank coal sources could suddenly become viable fuel sources for power plants compared with the more traditionally used bituminous and anthracite coals. The economical use of lower-sulfur subbituminous and lignite coals, in addition to removal of undesirable elements found within the coal that causes pollution, would also be greatly beneficial to the environment.